The present invention relates to the analysis of downhole fluids in a geological formation. More particularly, the present invention relates to apparatus and methods for downhole optical analysis of formation fluid contaminated by oil based mud filtrate.
Schlumberger Doll Research, the assignee of this application has provided a commercially successful borehole tool, the MDT (a trademark of Schlumberger), which extracts and analyzes a flow stream of fluid from a formation in a manner substantially as set forth in co-owned U.S. Pat. Nos. 3,859,851 and 3,780,575 to Urbanosky. The analyzer module of the MDT, the OFA (a trademark of Schlumberger) determines the identity of the fluids in the MDT flow stream. Mullins, in co-owned U.S. Pat. No. 5,266,800, teaches that by monitoring optical absorption spectrum of the fluid samples obtained over time, a real time determination can be made as to whether a formation oil is being obtained as opposed to oil based mud (OBM) filtrate. In particular, the Safinya patent discloses a borehole apparatus which includes a testing chamber, means for directing a sample of fluid into the chamber, a light source preferably emitting near infrared rays and visible light, a spectral detector, a data base means, and a processing means. Fluids drawn from the formation into the testing chamber are analyzed by directing the light at the fluids, detecting the spectrum of the transmitted and/or backscattered light, and processing the information accordingly. Prior art equipment is shown in FIGS. 1A-1C.
Because different fluid samples absorb energy differently, the fraction of incident light absorbed per unit of path length in the sample depends on the composition of the sample and the wavelength of the light. Thus, the amount of absorption as a function of the wavelength of the light, hereinafter referred to as the xe2x80x9cabsorption spectrumxe2x80x9d, has been used in the past as an indicator of the composition of the sample. For example Safinya, in U.S. Pat. No. 4,994,671, teaches, among other things, that the absorption spectrum in the wavelength range of 0.3 to 2.5 microns can be used to analyze the composition of a fluid containing oil. The disclosed technique fits a plurality of data base spectra related to a plurality of oils and to water, etc., to the obtained absorption spectrum in order to determine the amounts of different oils and water that are present in the sample.
When the desired fluid is identified as flowing in the MDT, sample capture can begin and formation oil can be properly analyzed and quantified by type. Samples are used to determined important fluid properties such as the gas-oil ratio (GOR), saturation pressure, wax and asphaltene precipitation tendency, fluid densities and fluid composition. These parameters help set various production parameters and also relate to the economic value of the reserve.
Prevalent use of oil based mud (OBM) in some markets has resulted in a premium placed on discriminating between OBM filtrate and crude oil. A variety of oils are used as the base for OBM such as diesel, synthetics such as C16 and C18 monoalkenes, and even crude oil. Due to the variety of base fluids and their overlapping properties with crude oils, it is difficult to identify a single signature of OBM to contrast it with crude oil. Furthermore, the use of a label or taggant for the OBM filtrate is often discouraged in part because of the difficulty in labeling at a fixed concentration 5000 barrels of mud and in part because mud engineers do not want to use any additives which may have an unknown significant consequence on drilling characteristics.
Mullins, in U.S. Pat. No. 5,266,800, teaches that by monitoring optical absorption spectrum of the fluid samples obtained over time, a real time determination can be made as to whether a formation oil is being obtained as opposed to OBM filtrate. As noted above, Mullins, in U.S. Pat. No. 5,266,800, discloses how the coloration of crude oils can be represented by a single parameter which varies of several orders of magnitude. The OFA was modified to include particular sensitivity towards the measurement of crude oil coloration, and thus filtrate coloration. During initial extraction of fluid from the formation, OBM filtrate is present in relatively high concentration. Over time, as extraction proceeds, the OBM filtrate fraction declines and crude oil becomes predominant in the MDT flowline. Using coloration, as described in U.S. Pat. No. 5,266,800, this transition from contaminated to uncontaminated flow of crude oil can be monitored.
U.S. Pat. Nos. 3,780,575 and 3,859,851 to Urbanosky, U.S. Pat. Nos. 4,860,581 and 4,936,139 to Zimmerman et al., U.S. Pat. No. 4,994,671 to Safinya et al., and U.S. Pat. Nos. 5,266,800 and 5,859,430 to Mullins are hereby incorporated herein by reference.
The applicants discovered that the measured optical density of a downhole formation fluid sample contaminated by OBM filtrate changes slowly over time and approaches an asymptotic value corresponding to the true optical density of formation fluid. The applicants also discovered that a calculated gas oil ratio (GOR), derived from measured optical density measurements of a downhole formation fluid sample contaminated by OBM filtrate also changes slowly over time and approaches an asymptotic value corresponding to the true GOR of formation fluid.
The applicants recognized the potential value, in borehole investigative logging, of a real time log of OBM filtrate fraction.
The applicants also discovered that it would be possible to estimate OBM filtrate fraction by measuring optical density values at one or more frequencies, curve fitting to solve for an asymptotic value, and using the asymptotic value to calculate OBM filtrate fraction.
The applicants also discovered that it would be possible, in like manner, to estimate GOR corrected for OBM filtrate fraction, and OD corrected for OBM filtrate fraction.
The applicants also discovered that it would be possible, in like manner, to predict future filtrate fraction as continued pumping flushes the region around the MDT substantially free of OBM filtrate.
The applicants recognized the need to provide appropriate tests to validate, or invalidate, asymptote analysis so as to screen out erroneous measurements caused, for example, by OBM filtrate entering the MDT tool through ineffective mudcake forms.
The applicants further recognized that such estimates would have value not only in boreholes, but also in established wells.
Therefore it is an object of the invention to provide a method and apparatus for determining oil based mud filtrate fraction in a borehole fluid sample that is contaminated by OBM filtrate.
It is another object of the invention to provide a method and apparatus for determining oil based mud filtrate fraction based on optical density (OD) for use when there is significant difference between the coloration of formation fluid and the coloration of oil based mud filtrate.
It is another object of the invention to provide a method and apparatus for determining oil based mud filtrate fraction based on gas oil ratio (GOR) for use when there is little or no difference between the coloration of formation fluid and the coloration of oil based mud filtrate.
It is another object of the invention to provide a method and apparatus for determining GOR of formation fluid corrected for OBM filtrate contamination.
It is another object of the invention to provide a method and apparatus for determining optical density (OD) of formation fluid corrected for OBM filtrate contamination.
It is another object of the invention to provide a method and apparatus for detecting the presence of particulates in the sample that would render optical density measurements invalid and sample capture premature, either because flushing is not yet complete or because ineffective mudcake forms are allowing continuous inflow of contaminating OBM filtrate.
It is another object of the invention to provide a method and apparatus for predicting the reduction of filtrate fraction for a specific extended pumping time.
It is another object of the invention to provide a method and apparatus for allowing the operator to pre-set specific extended pumping time in accordance with a predicted reduction of filtrate fraction.
It is another object of the invention to provide a method and apparatus for initiating sample capture when computed contamination fraction exhibits stable asymptotic convergence and is below a predetermined value.
It is another object of the invention to provide a method for compensating for the effects of scattering.
It is another object of the invention to provide a method for compensating for the effects of varying pump rate.
Using an Asymptotic Curve Associated With OBM Filtrate
A special technical feature of the present invention is the use of an asymptotic curve derived from measurements of a parameter indicative of OBM filtrate contamination decrease as the borehole is pumped, to assess several qualities of the downhole fluid.
Determining OBM Filtrate Fraction From OD/Coloration
A preferred embodiment of the method for determining OBM filtrate fraction of borehole fluid from measured OD values uses a borehole tool having a pump, a flowline, and an optical analyzer. The method includes pumping borehole fluid through the analyzer; measuring optical density (OD) of borehole fluid to produce a series of OD values at intervals of time; and calculating an OD asymptotic ratio indicative of OBM filtrate fraction. Calculating the OD asymptotic ratio includes solving a first mathematical function for coefficients by fitting the series of OD values to the first mathematical function, then using at least one of the coefficients in a second mathematical function to determine OBM filtrate fraction. The first mathematical function expresses OD as a function of time, the first mathematical function has one coefficient representing an unknown asymptotic value, and at least one term which decreases with time. The first mathematical function is OD(t)=m1+m2txe2x88x92x, in which m1 is a first coefficient representing the unknown OD asymptotic value, m2 is a second coefficient, and x is a selected decay value, approximately 0.5, and within the range 0.2 to 0.8. The second mathematical function is Fraction=(m1xe2x88x92OD)/m1, or Fraction=|(m1xe2x88x92OD)|/m1, in which m1 is an OD asymptotic value determined by solving for coefficients, and OD is an OD value derived from the series of OD values. Measuring OD includes illuminating borehole fluid with light of wavelength in the visible spectrum selected in accordance with coloration contrast between formation fluid and OBM filtrate. The wavelength is selected as being the shortest wavelength that yields an OD in the range 0.05 to 2.0. The first wavelength selected is approximately 537xc3x9710xe2x88x929 m (537 nm).
Alternatively, the wavelength is selected in accordance with contrast between the OD of condensate dissolved in the formation fluid and the OD of OBM filtrate, and is proximate to a methane peak, and on a lower wavelength shoulder of the methane peak. The preferred embodiment includes validating the calculated asymptotic ratio by testing for scattering at wavelength 1600xc3x9710xe2x88x929 m (1600 nm), to determine if OD is less than 0.02. The preferred embodiment also includes validating the calculated asymptotic ratio by testing for monotonically changing OD values, indicative of color change with time, to verify asymptotic convergence of OD values, including testing for m2 less than 1 or |m2| less than 1. The preferred embodiment also includes validating the calculated asymptotic ratio by repeating the steps needed to produce a series of asymptotic values; and testing the series of asymptotic values for stability by testing for (m1xe2x88x92m1prev.)/m1 less than 0.05 or |(m1xe2x88x92m1prev.)|/m1 less than 0.05.
Determining OBM Filtrate Fraction From OD/GOR
A preferred embodiment of the method for determining OBM filtrate fraction of borehole fluid from calculated GOR values uses a borehole tool having a pump, a flowline, and an optical analyzer. The method includes pumping borehole fluid through the analyzer; illuminating the borehole fluid with light in the visible spectrum and with near infra-red (NIR) light at a wavelength associated with gas; detecting optical absorbance in the visible spectrum to produce a visible spectrum optical density value and NIR absorbance to produce an NIR optical density value; calculating gas oil ratio (GOR) as the ratio of the NIR optical density value to the visible spectrum optical density value; repeating steps a) to d) to produce a series of GOR values at intervals of time; and calculating a GOR asymptotic ratio indicative of OBM filtrate fraction. Calculating the GOR asymptotic ratio includes solving a third mathematical function for its coefficients by fitting the series of OD values to the third mathematical function, then using at least one of the coefficients in a fourth mathematical function to determine OBM filtrate fraction. The third mathematical function expresses GOR as a function of time, having one constant coefficient representing an unknown asymptotic value, and at least one term which decreases with time. The third mathematical function includes GOR(t)=r1+r2txe2x88x92y, in which r is a first constant coefficient representing the unknown GOR asymptotic value, r2 is a second constant coefficient, and y is a selected decay value of approximately 0.5 and within the range 0.2 to 0.8. The fourth mathematical function includes Fraction=(r1xe2x88x92OD)/r1, in which r1 is the asymptotic value determined by solving for coefficients, and GOR is a GOR value derived from the series of GOR values.
Determining GOR Corrected For OBM Filtrate Fraction
A preferred embodiment of the method for determining gas oil ratio (GOR) of formation fluid corrected for OBM filtrate contamination includes producing a series of GOR values at intervals of time, and calculating a GOR asymptotic value by fitting the series of GOR values to the above-mentioned third mathematical function.
Determining OD Corrected For OBM Filtrate Fraction
A preferred embodiment of the method for determining optical density (OD) of formation fluid corrected for OBM filtrate contamination includes producing a series of OD values at intervals of time, and calculating an OD asymptotic value by fitting the series of OD values to the above-mentioned first mathematical function.
Correcting For Wavelength-Independent Scattering
A preferred embodiment of the method for determining a quality of downhole fluid uses the difference between signals from two channels at different wavelengths to reduce unwanted effects from wavelength-independent scattering.
Minimizing Effects of Varying Pump Rate
A preferred embodiment of the method for determining a quality of downhole fluid uses curve fitting on a volume axis to reduce errors due to varying pump rate.
Minimizing Effects of Wavelength-Dependent Scattering
A preferred embodiment of the method for determining a quality of downhole fluid includes delaying curve fitting until the difference signal is increasing with time, so as to reduce an unwanted effect of wavelength-dependent scattering.
Validating Initiation of Sample Capture
A preferred embodiment of the method for validating initiation of sample capture of borehole fluid, uses a borehole tool having a pump, a flowline, an optical analyzer, and means for capturing a sample; the pump pumping borehole fluid through the analyzer.
The method further includes measuring optical density (OD) of borehole fluid, at a wavelength of approximately 1600xc3x9710xe2x88x929 m (1600 nm) to test for scattering; and testing for OD less than 0.02.
The method further includes measuring optical density (OD) of borehole fluid produce a series of optical density values at intervals of time; calculating an asymptotic value indicative of optical density of formation fluid from the series of optical density values; repeating the steps needed to produce a series of asymptotic values; and testing for asymptotic values monotonicaly changing at less than a predetermined rate.
Predicting OBM Filtrate Fraction After Further Pumping
A preferred embodiment of the method for predicting OBM filtrate fraction of borehole fluid after a predefined second period of pumping, uses a borehole tool having a pump, a flowline, and an optical analyzer. The method includes pumping borehole fluid through the analyzer; illuminating the borehole fluid with light in the visible spectrum and with near infra-red (NIR) light at a wavelength associated with gas; detecting optical absorbance in the visible spectrum to produce a visible spectrum optical density value and NIR absorbance to produce NIR optical density value; calculating GOR as the ratio of the NIR optical density value to the visible spectrum optical density value; repeating during a first period of pumping the steps needed to produce a series of GOR values at intervals of time; fitting the series of ratio values to a mathematical function of the form GOR(t)=r1+r2txe2x88x92y, in which r1 is the unknown asymptotic value, r2 is a constant, and y is a selected decay value, to solve for r1 and r2; and solving equation FRACTION=[r2TPmxe2x88x92y]/r1, where TPm is the predefined second period of pumping.
Apparatus
A preferred embodiment of the borehole apparatus of the present invention includes a borehole tool including a flowline with an optical cell, a pump coupled to the flowline for pumping borehole fluid through the cell, and an analyzer optically coupled to the cell, the analyzer configured to produce OD values; and control means for accepting OD values and calculating therefrom an asymptotic value.
In one embodiment the asymptotic value is an OD asymptotic value indicative of OBM filtrate fraction.
In another embodiment the asymptotic value is a GOR asymptotic ratio indicative of OBM filtrate fraction.
In another embodiment the asymptotic value is a GOR asymptotic value indicative of GOR corrected for OBM filtrate fraction.
In another embodiment the asymptotic value is a GOR asymptotic value indicative of GOR corrected for OBM filtrate fraction.
In another embodiment the asymptotic value is an OD asymptotic value indicative of OD corrected for OBM filtrate fraction.
In another embodiment the control means further includes means for testing OD values to validate measurement by confirming asymptotic convergence.
In another embodiment the control means further includes means for testing OD values to validate measurement by confirming stable asymptote.
In another embodiment the asymptotic value is an OD asymptotic value indicative of OBM filtrate fraction after a selected additional pumping time.
Stored Program
A preferred embodiment of the stored program of the present invention includes a computer usable medium having computer readable program code thereon, the medium adapted for use with borehole apparatus, the program code including code structured to accept a series of OD values and to calculate from the OD values an asymptotic value indicative of OBM filtrate fraction, an asymptotic value indicative of GOR of formation fluid and an asymptotic value indicative of OD of formation fluid.